Wednesday, January 28, 2015

Cost of solar power (48)

According to charts available at this website, the Atacama Desert has the best solar resource in the world, as much as 3,500 kWh/m^2 per year.  Moreover this solar resource occurs in a region with significant electricity demand from mining and metal processing operations.  Couple that with all the usual drivers for renewable energy (decarbonisation, price reduction in PV systems, energy security, …) and it’s no surprise that there is now significant solar power generation activity in the Atacama Desert.

The 100 MW Amanecer PV plant in the Copiapo municipality was opened on 8 June 2014.  At the time of opening it was the largest PV plant in South America.  The 280 Ha installation is at an altitude of 1,165 m above sea level, comprises 310,000 Sun Edison panels and will provide 270 GWh of electricity to the local grid.  Construction took only 6 months.

The output of the plant will provide 15% of the local electricity demand of the Chilean steel group CAP, the largest iron ore and pellet producer on the American Pacific Coast.  The cost of the plant has been variously reported as USD 250 million and USD 260.5 million, the latter figure seeming the more authoritative.

We can now proceed to analyse the LCOE using my standard assumptions:
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.

For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Amanecer project are as follows:

Cost per peak Watt              USD 2.61/Wp
LCOE                                     USD 110/MWh

The components of the LCOE are:
Capital           {0.094 × USD 260.6×106}/{270,000 MWhr} = USD 91/MWhr
O&M              {0.020 × USD 260.6×106}/{270,000 MWhr} = USD 19/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014

Conclusion

You can compare results with my LCOE graphic.

The LCOE for the Amanecer project is outstanding, the best I have analysed so far.  The installation cost per peak Watt (USD 2.61/Wp) is nothing special these days, but the annual output is superb.   I calculate the Capacity Factor as 270,000 / (100×365×24) = 0.308.
 
That’s what one should expect with the best solar resource in the world!

Monday, January 26, 2015

Real cost of coal-fired power (update)


In April 2011, I made a blog post about the real cost of coal-fired power, particularly when the social cost of carbon (SCC) is included.  Since then, there have been a couple of big developments – (1) the cost of coal has fallen (not increased as I expected in 2011) and (2) there is increasing economic evidence that the SCC should be higher.  It’s time for me to update the previous post.
 
Let’s take the cost of coal first of all.
 
Here’s the cost (USD/tonne) of Australian thermal coal, 12,000 BTU/lb (27.912 GJ/t), less than 1% sulphur, 14% ash, FOB Newcastle or Port Kembla (source).    The past few years have not been good for coal miners, even allowing for the recent fall in the Australian dollar, and the price of coal is still in a downtrend.
 
 
What about the SCC?

In evaluating the SCC, the sort of issues to be considered are
  • land disturbance
  • methane emissions from mines
  • carcinogens
  • public health burden of communities
  • fatalities due to coal transport
  • emissions of air pollutants from combustion
  • effects of mercury emissions (lost productivity, mental health, cardiovascular)
  • climate damage from combustion emissions (CO2, N2O, soot)
Let me now refer you to a recent excellent article by Dana Nuccitelli.  Citing work by Moore & Diaz of Stanford University, he argues the costs of climate change have been underestimated because climate change will slow the rate of GDP growth in developing countries.  Moore & Diaz argue that the SCC is between USD 70/t and USD 400/t depending on assumptions in their model, with a best estimate of USD 200/t CO2.

(Meanwhile, the US Government has recently set the SCC as USD 37/t, increased from USD 22/t and accompanied by outraged protest from the Republican party.)

I’ll now calculate the Levelised Cost of Electricity (LCOE) for coal-fired power for different Capacity Factors and different Social Costs of Carbon.  This will be done under my standard assumptions:

  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years),
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.


Given the risk of future stranded assets and hence the difficulty in obtaining finance for new coal-fired power generation (see this reference to Bloomberg), the assumed cost of finance above is probably on the low side.  
The LCOE calculations are made under the following additional assumptions

  • specific capital cost Rankine-cycle steam plant: AUD 1,500,000/MW
  • thermodynamic efficiency: 0.39
  • cost of coal: USD 65/t currently equivalent to AUD 81.25/t
  • fraction of coal that is carbon: 0.737
  • energy content of coal: 27.9 GJ/t
The LEC is then calculated for
  • SCC in the range AUD 0 to AUD 200 per tonne
  • Capacity Factors in the range 0.7 to 1.0 (the Capacity Factor is the fraction of time that the generator is active)
Here are the updated results for the LCOE in AUD per MWh (click for a clearer image):





For these parameters, 894 kg CO2 is emitted per MWh.  So, as a rule of thumb, every $ increase in the SCC translates to almost one extra $ on the LCOE when expressed in $/MWh.
 
Conclusion
 
If the official US SCC of $37/t were to be adopted in Australia, the cost of coal-fired power would be increased by about $35/MWh.  If the best-estimate (USD 200/t) for the SCC is applied, then coal-fired power would be completely uncompetitive with renewable forms of energy such as wind and solar.  The risk of stranded assets would further weaken the case for coal-fired power generation.

 
 
 

 

Wednesday, December 17, 2014

Cost of solar power (47)

RenewEconomy has a story today about a PV installation at a macadamia processing plant in northern New South Wales.  Output from the macadamia farm is used by the proprietors, Brookfarm, to make muesli.

This is another feel-good instance in which proprietors of small- to medium-sized enterprises save on their power bills by installing a PV system that meets much of their power requirements during the day.

This particular installation is interesting in that the proprietors installed half of the panels facing east and half facing west.  That way, they help to meet their power requirements in the early morning and late afternoon.

RenewEconomy reported that the peak power is 94.2 kW and that the system cost AUD 233,000.  The article mentions that approximately one third of the installation cost is recovered from sale of small-scale renewable energy certificates.  

I’m grateful to Brookfarm for kindly providing an estimate of the annual output, namely 144 MWh AC grid voltage.  From this, I calculate the Capacity Factor will be 1000 × 144 / (24 × 365 × 94.2) = 0.175.  That figure is no surprise to me given the layout of the panels and the fact that the Northern Rivers region is often cloudy in summertime.

We can now proceed to analyse the LCOE using my standard assumptions:

  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.

For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Brookfarm project are as follows:

Cost per peak Watt              AUD 2.47/Wp
LCOE                                     AUD 184/MWh

The components of the LCOE are:
Capital           {0.094 × AUD 0.233×106}/{144 MWhr} = AUD 152/MWhr
O&M              {0.020 × AUD 0.233×106}/{144 MWhr} = AUD 32/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)


Conclusion

You can compare results with my LCOE graphic.

The LCOE for the Brookfarm project compares favourably with recent projects of similar size, e.g. Kalgoorlie-Boulder (AUD 256/MWh) and Ferngrove Winery (AUD 298/MWh in mid-2013, a scant 18 months ago).

Given the high cost of grid-supplied power in Australia, I expect the Brookfarm project will have a short payback period and will also attract favourable publicity.  I congratulate the proprietors.

Tuesday, November 18, 2014

Cost of solar power (46)

The Australian federal government is currently doing everything it can to destroy the local renewables industry.  That’s a scarcely believable situation, but it is true.  It merely reflects the very close relationship between the government and the fossil fuel industry in this country.

Even in gloomy times like the present, however, an occasional nugget of good news comes along.  In this case, it’s a large nugget!  Please read on …

Way back in 2011 when the current opposition was in government, there was a federal program called Solar Flagships.  The idea was to use government funds to provide substantial funding for large solar installations.  Early success was expected, to be followed by rapid build-up of a sunrise industry.

That didn’t happen.  The Solar Flagships program was not successful.  The targets were too ambitious, markets were not ready, human capital was not able to bring projects to a successful conclusion, power take-off agreements weren’t arranged and entrenched inertia against renewables was too strong.  A review of the experience is available here.  It is very blunt and makes fascinating reading.

One of the successful Solar Flagship proposals was the Moree Solar Farm, which I blogged about here.  It was for a utility-scale project (150 MW, AUD 923 million) at a good site in northern New South Wales, and was announced in June 2011.  My estimate for the Levelised Cost of Electricity (LCOE) was AUD 263/MWh.  (Please note, this is an adjusted figure, arrived at using 2% annual O&M cost, which is my current practice.)

The Moree Solar Farm proposal limped along in a near-death state for three years until just recently a revised proposal was announced for which funding was committed.  This project is going to go ahead as announced by ARENA here.

Construction and operation of the system will be carried out by Moree Solar Farm Pty Ltd, a subsidiary of the Spanish company FRV.  Construction will take place over 2014-15, so let’s assume that the launch will be in December 2015.

The new project will have peak power 56 MW grid-connected AC (70 MW DC ex-modules).  The total project value is AUD 164 million, of which ARENA is providing AUD 101.7 million.  The total estimated output over the 30-year lifetime of the system is 4,000 GWh, or 133.3 GWh per year.

From a technical point of view, the system will use polycrystalline modules and a single-axis tracking system.  I calculate the Capacity Factor will be 1000 × 133.3 / (24 × 365 × 56) = 0.272.  That is a little less than I expected for a system with single-axis tracking, but let’s stay with the estimate.

We can now proceed to analyse the LCOE using my standard assumptions:

  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.


For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the new Moree project are as follows:

Cost per peak Watt              AUD 2.9/Wp
LCOE                                     AUD 141/MWh

The components of the LCOE are:
Capital           {0.094 × AUD 164×106}/{133×103 MWhr} = AUD 116/MWhr
O&M              {0.020 × AUD 164×106}/{133×103  MWhr} = AUD 25/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)


Conclusion

You can compare results with my LCOE graphic.

In the space of just over three years, the LCOE for projects at Moree fell from AUD 263 to AUD 141 per MWh, a 47% reduction (actually more if inflation is taken into account).  I think that would accord with the expectations of most observers.

The LCOE for the new Moree project can be compared with recent large installations in Australia on the list above: Nyngan & Broken Hill (AUD 205), Mugga Lane (AUD 137) and Coree (AUD 163).


What will be the LCOE in three years?  It seems to me that the future – in which utility-scale PV installations out-compete new-build fossil fuel projects – is nearly with us.

Tuesday, October 28, 2014

Cost of solar power (45)

I was born, raised and educated in Western Australia and still retain a soft spot for the huge state despite having lived elsewhere for 41 years.  So it’s a pleasure to write a feel-good story about a new PV installation at the South Boulder Wastewater Treatment Plant, 600 km inland from the WA state capital Perth.

The mayor of the City of Kalgoorlie-Boulder, Ron Yuryevich, says the installation
is the largest of the four solar PV installations undertaken by the City of Kalgoorlie-Boulder in the past two years and is another example of the City’s commitment to long term sustainability”.
Power from the 150 kW ground mounted installation will be used in the City’s waste water treatment plant.  100% of the waste water is re-used for watering of parks and sporting facilities, which is very useful since Kalgoorlie-Boulder has a semi-arid environment.  The system is estimated to provide electricity savings of $60,000 per year and also to provide CO2 abatement of 230 tonnes per year.

In technical terms, the system has 500 Suntech panels (each of 300 W), two 75 kW Fronius inverters and a Schletter racking system.  EcoGeneration reports that the cost of the system is $595,000 (including 10% goods and services tax).  The system was commissioned in August 2014.

As for the annual output of the system, the City of Kalgoorlie-Boulder kindly informed me that their projections were 260-270 MWh/yr.  Let’s take 265 MWh/yr, which corresponds to a Capacity Factor of (265 × 1000) / (150 × 24 × 365) = 0.20, a useful benchmark figure for future reference.

We can now proceed to analyse the LCOE using my standard assumptions:
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.

 For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Kalgoorlie-Boulder project are as follows:

Cost per peak Watt              AUD 4.0/Wp
LCOE                                     AUD 256/MWh

The components of the LCOE are:
Capital           {0.094 × AUD 595,000}/{265 MWhr} = AUD 211/MWhr
O&M              {0.020 × AUD 595,000}/{265 MWhr} = AUD 45/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)

Conclusion

You can compare results with my LCOE graphic.

For international comparisons, the LCOE should really be adjusted for the effect of the Australian goods and services tax.  That would reduce the estimates by 9.09%, giving AUD 233/MWh.  The LCOE is slightly high compared to recent international installations, but that reflects the fact that Australia is a high-cost place, even in spite of recent falls in the Aussie dollar.  Also Kalgoorlie-Boulder is a remote location with significant transport costs for hardware.


Tuesday, October 21, 2014

Cost of storage (2013 Sandia report)


We hear every day that the cost of storage is falling rapidly, with obvious implications for the prospects of renewable power generation.  I accept that most of these statements are made in good faith, but some are clearly optimistic.  Where can one find objective expert information about the cost of storage?

I was pleased to read a recent report (PDF, 12 MB) [1] from the Sandia National Laboratories that gives detailed information about the costs of various forms of storage.  The Sandia Laboratories were originally formed for nuclear research and still have major involvement with nuclear weapons, but they also undertake other forms of research, including energy and climate.  I would say Sandia has exceptionally high credibility.

The Sandia report is dated July 2013.  The authors first describe various uses of storage in the electricity system:
  • bulk energy services (energy time-shift, supply capacity)
  • ancillary services (regulation, spinning reserve, voltage support, black start, load following, frequency response)
  • transmission infrastructure services (upgrade deferral, congestion relief)
  • distribution infrastructure services (upgrade deferral)
  • customer energy management services (power quality, power reliability, retail energy time-shift, demand charge management)

They then survey the actual cost of installed systems.  In their words:
“More than 50 battery original equipment manufacturers (OEMs), power electronics system providers, and system integrators were surveyed and asked to provide performance, cost, and O&M data for energy systems they could offer for various uses of storage.”

Although some of the data comes from 2010 and 2011, all costs are expressed in 2012 USD.  The comprehensive cost estimates include:

  • energy storage system (equipment, installation, enclosures)
  • owner interconnection (equipment, installation, enclosures)
  • packing and shipping
  • utility connection (equipment, installation)
  • Balance of Plant costs (civil engineering only)
  • general contractor facilities
  • engineering fees
  • project contingency (@ 0-15% of install)
  • process contingency (@ 0-15% of battery)
The Sandia report thus gives a snapshot of storage costs in the U.S., as best as could be done in mid-2013.  Different metrics are provided such as round trip efficiency, installed cost in $/kW or $/kWh, and LCOE in $/MWh.

The figure below was prepared from data sheets in Appendix B of the report.  It shows the initial installed capital cost in $/kWh for 19 different types of storage installations.  The technologies do not include thermal storage of energy as in Concentrated Solar Thermal installations.  I have also omitted results for flywheel storage, as this is so expensive as to be off-the-scale in the figure.

Initial capital cost for storage systems (2012 USD / kWh).  Categories described below.


The categories are:


1          greenfield pumped hydro (bulk storage)
2          compressed air energy storage (bulk storage)
3          Na-S (bulk storage, utility T&D)
4          Na-Ni-Cl (bulk storage, utility T&D, commercial and industrial)
5          Va-redox (bulk storage, utility T&D, commercial and industrial)
6          Fe-Cr (bulk storage, utility T&D, commercial and industrial)
7          Zn-Br (bulk storage, frequency regulation, utility T&D grid support)
8          Zn-Br (distributed storage, commercial and industrial)
9          Zn-Br (small residential)
10        Zn-air (bulk storage, utility T&D, commercial and industrial)
11        advanced Pb-acid (bulk storage)
12        advanced Pb-acid (frequency regulation)
13        advanced Pb-acid (utility T&D)
14        advanced Pb-acid (distributed storage)
15        advanced Pb-acid (commercial and industrial)
16        Li-ion (frequency regulation, renewables)
17        Li-ion (utility T&D grid support)
18        Li-ion (distributed storage)
19        Li-ion (commercial and industrial)

It is important to note that project lifetimes differ for the various technologies – it’s 60 years for pumped hydro, 40 years for compressed air energy storage and 15 years for all the battery technologies.

The initial capital costs for pumped hydro (Category 1) and compressed air energy storage (Category 2) are very good.  (Incidentally other energy storage metrics, particularly Energy Stored on Energy Invested, are also very good for pumped hydro and compressed air energy storage.)  Category 6 (Fe-Cr technology) has good results for installations dating back to 2011.  Results for Category 10 (Zn-air technology) seem good, but the report notes these are for systems that might be built in the future.

Lead-acid systems (Categories 11-15) were still cheaper than Li-ion systems (Categories 16-19) at the time the report was completed.  The flow batteries (Categories 5 and 7-9) give mixed results, which one imagines will be improved with further development.

Conclusion

According to the Sandia report, battery storage costs are still quite high when all costs and the project lifetimes (15 years) are taken into account.  Battery technology is clearly developing quickly, and I look forward to follow-up reports from Sandia or other sources.

Anthony Kitchener is thanked for mentioning this report to me.

Reference

[1] A.A. Akhil et al., “DOE/EPRI 2013 Electricity Storage Handbook in Collaboration with NRECA”, Sandia Report SAND2013-5131 (July 2013).